This disclosure relates generally to enhanced hydrocarbon recovery from subterranean “tight” geological reservoir formations. “Tight” formations are known within the hydrocarbon extraction industry as geologic formations having a permeability less than 100 microdarcies. Recent technology advances have made possible “primary production”, that is, hydrocarbons transported from subsurface reservoir formations to the Earth's surface substantially entirely by the energy contained in such subsurface hydrocarbon reservoir formations and/or fluid systems and artificial lift methods, from such reservoir formations. This disclosure relates more specifically to production methods to enhance “secondary” hydrocarbon extraction from such subsurface hydrocarbon reservoir formations, called “secondary recovery.” Secondary recovery is understood by those skilled in the art to mean hydrocarbon extraction beginning after the primary phase of production and may be characterized by injection of fluids comprised of liquid or gaseous phases into the reservoir formation.
It is known in the art to drill and complete wells in tight formations and then use hydraulic fracturing treatments to improve fluid conductivity (permeability) along paths to the wellbore for hydrocarbons originally existing in the pore spaces of formations such as shale, mud, siltstone and other types of tight formations. Hydraulic fracturing treatments result in increased conductivity by injecting at high pressure a mix of fluids and proppant with beneficial chemical additives to open fractures in the formation. The fluid under pressure creates fractures in the formation and the proppant supports or “prop” the fractures open after the fluid injection has ended. The propped fractures enable primary recovery of hydrocarbons.
The reservoirs contemplated by this disclosure have low permeability and would be difficult to sustain a secondary recovery operation due to the costs associated with pumping fluid through a reservoir that has not been propped by hydraulic fracture. One of the techniques known in the art for hydraulic fracturing includes the use of a surfactant or surfactant blend (usually a mix of a surfactant and a co-surfactant) to improve the recovery of the largely aqueous phase of fracture treatment fluid from a wellbore that has been subjected to fracture treatment. It is believed that by increasing the surface recovery of fracture treatment water the fracture will have less relatively immobile fluid phases that restrict the effective flow rates or relative permeability of hydrocarbons in the formations back to the hydraulically fractured well. While the performance of the surfactants or surfactant blends vary based on compositions thereof, formation water salinity, temperature and pressure of the reservoir formation, some surfactants or blends are effective at creating an emulsion of varying scales of either water-in-oil or oil-in-water composition. Tight reservoirs are known in the art to be developed with several horizontal wells in close proximity to each other to maximize the contact of each well's hydraulic completion (i.e., the fracture zone subtended by each well) with the formation without having any well spaced close enough to any adjacent wells so as to have adjacent wells' fracture zones extending into the same hydrocarbons located in the reservoir.